SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
_______________________________
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended: March 31,June 30, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________
Commission file number: 0-593
CHESAPEAKE UTILITIES CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 51-0064146
(State of other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
861 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices) (Zip Code)
(302) 734-6754
(Registrant's Telephone Number, Including Area Code)
________________________________________________________
(Former name, former address and former fiscal year, if changed since last
report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [ ].
Common Stock, par value $.4867 - 3,690,8943,700,688 shares issued as of June 30, 1995,
of which 10,2194,135 are held in treasury, as of March 31, 1995.treasury.
PART I
FINANCIAL INFORMATION
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
MARCH 31, DECEMBERJune 30, December 31,
1995 1994
ASSETSAssets (Unaudited)
------------ ------------
PROPERTY, PLANT AND EQUIPMENT----------- -----------
Property, Plant And Equipment
Natural gas distribution $59,454,465$61,835,512 $57,773,632
Natural gas transmission 24,712,91824,885,913 24,546,916
Propane distribution 18,329,58418,507,980 18,289,571
Information technology services and other 8,909,4689,496,740 8,618,014
Gas plant acquisition adjustment 795,004 795,004
------------ --------------------------------------
Total property, plant and equipment 112,201,439115,521,149 110,023,137
Less: Accumulated depreciation and amortization (35,822,253)(36,925,922) (34,710,478)
------------ --------------------------------------
Net property, plant and equipment 76,379,18678,595,227 75,312,659
------------ ------------
INVESTMENTS 1,976,988--------------------------
Investments 1,873,407 1,641,851
------------ ------------
CURRENT ASSETS--------------------------
Current Assets
Cash and cash equivalents 542,855259,005 398,751
Accounts receivable, less allowance 7,370,116 8,416,293
for uncollectibles 8,779,084 8,416,293
Materials and supplies, at average cost 860,797864,164 797,147
Propane inventory, at average cost 1,086,394967,971 1,411,384
Storage gas prepayments 1,181,5942,237,041 3,467,281
Underrecovered purchased gas costs 109,025
Income taxes receivable 836,813
Prepaid expenses 476,248902,331 855,107
Deferred income taxes 1,691,8251,896,146 1,290,680
------------ --------------------------------------
Total current assets 14,618,79714,496,774 17,582,481
------------ ------------
DEFERRED CHARGES AND OTHER ASSETS--------------------------
Deferred Charges and Other Assets
Intangible assets, net of accumulated amortization 1,814,3651,687,512 1,941,239
Environmental cost 7,457,0027,401,945 7,462,647
Order 636 transition cost 1,840,4521,719,573 2,020,732
Other deferred charges 2,092,1432,135,887 2,309,008
------------ --------------------------------------
Total deferred charges and other assets 13,203,96212,944,917 13,733,626
------------ ------------
TOTAL ASSETS $106,178,933--------------------------
Total Assets $107,910,325 $108,270,617
============ ======================================
The accompanying notes are an integral part of these financial statements.
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
MARCH 31, DECEMBERJune 30, December 31,
1995 1994
CAPITALIZATION AND LIABILITIESCapitalization and Liabilities (Unaudited)
------------ ------------
CAPITALIZATION----------- -----------
Capitalization
Stockholders' equity
Common Stock, par value $.4867 per share;
(authorized 12,000,000 shares; issued 3,680,6753,700,688
and 3,653,182 shares, respectively) $1,796,271$1,801,039 $1,785,514
Additional paid-in capital 17,143,29117,301,961 16,834,823
Retained earnings 22,310,65322,243,014 19,480,374
Less: Treasury stock, at cost; (10,219(4,135 and
15,609 shares, respectively) (65,378)(26,476) (99,842)
Unearned compensation - restricted stock (652,402) (696,679)
awards (748,475) (696,679)
Net unrealized loss on marketable (141,412) (241,609)
securities
(80,680) (241,609)
------------ --------------------------------------
Total stockholders' equity 40,355,68240,525,724 37,062,581
Long-term debt, net of current portion 24,254,63923,909,138 24,328,988
------------ --------------------------------------
Total capitalization 64,610,32164,434,862 61,391,569
------------ ------------
CURRENT LIABILITIES--------------------------
Current Liabilities
Current portion of long-term debt 1,236,3491,249,349 1,348,080
Short-term borrowings 3,000,0003,500,000 8,000,000
Accounts payable 5,178,8316,236,916 7,385,590
Refunds payable to customers 832,335658,244 567,817
Overrecovered purchased gas costs 564,1231,316,633
Accrued interest 656,423682,408 691,949
Dividends payable 828,152831,724 803,700
Accrued income taxes 1,629,4341,384,029
Other accrued expenses 2,208,0722,310,412 2,225,097
------------ --------------------------------------
Total current liabilities 16,133,71918,169,715 21,022,233
------------ ------------
DEFERRED CREDITS AND OTHER LIABILITIES--------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 8,673,7898,582,045 8,700,472
Deferred investment tax credits 977,239963,535 986,062
Environmental liability 6,572,6416,500,022 6,642,092
Accrued pension costs 2,629,9342,641,134 2,530,904
Order 636 transition liability 1,840,4521,719,573 2,020,732
Other liabilities 4,740,8384,899,439 4,976,553
------------ --------------------------------------
Total deferred credits and other liabilities 25,434,89325,305,748 25,856,815
------------ ------------
TOTAL CAPITALIZATION AND LIABILITIES $106,178,933--------------------------
Total Capitalization and Liabilities $107,910,325 $108,270,617
============ ======================================
The accompanying notes are an integral part of these financial statements.
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
(UNAUDITED)
For the Quarter Ended
June 30,
1995 1994
--------------------------
Operating Revenues $22,074,663 $19,868,566
--------------------------
Operating Expenses
Purchased gas costs 12,926,940 12,511,333
Operations 4,771,005 4,596,300
Maintenance 506,894 554,440
Depreciation and amortization 1,335,653 1,301,700
Other taxes 706,523 657,817
Income taxes 458,306 (341,574)
--------------------------
Total operating expenses 20,705,321 19,280,016
--------------------------
Operating Income 1,369,342 588,550
Other Income and Deductions 87,418 (39,244)
--------------------------
Income Before Interest Charges 1,456,760 549,306
Interest Charges 692,675 665,890
--------------------------
Net Income $764,085 ($116,584)
==========================
Weighted Average Number of Common Shares Outstanding 3,692,515 3,625,892
==========================
Earnings Per Share of Common Stock (1):
Net income $0.21 ($0.03)
==========================
Fully Diluted Earnings Per Share of Common Stock (1):
Net income $0.21 ($0.03)
==========================
The accompanying notes are an integral part of these financial statements.
(1) See Exhibit 11 - Computation of Primary and Fully Diluted Earnings
Per Share
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
(UNAUDITED)
FOR THE QUARTER ENDED
MARCH 31,For the Six Months Ended
June 30,
1995 1994
------------ ------------
OPERATING REVENUES $30,896,798 $36,009,510
------------ ------------
OPERATING EXPENSES--------------------------
Operating Revenues $52,971,460 $55,878,077
--------------------------
Operating Expenses
Purchased gas costs 16,972,091 21,650,99529,899,031 34,162,328
Operations 4,953,206 5,099,2159,724,209 9,695,515
Maintenance 411,497 427,092918,392 981,532
Depreciation &and amortization 1,331,274 1,347,1642,666,927 2,648,865
Other taxes 866,917 849,8721,573,440 1,507,689
Income taxes 2,030,851 2,312,567
------------ ------------2,489,157 1,970,995
--------------------------
Total operating expenses 26,565,836 31,686,905
------------ ------------
OPERATING INCOME 4,330,962 4,322,605
OTHER INCOME AND DEDUCTIONS 44,260 64,064
------------ ------------
INCOME BEFORE INTEREST CHARGES 4,375,222 4,386,669
INTEREST CHARGES 716,791 640,582
------------ ------------
NET INCOME $3,658,431 $3,746,087
============ ============
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 3,671,041 3,598,481
============ ============
EARNINGS PER SHARE OF COMMON STOCK47,271,156 50,966,924
--------------------------
Operating Income 5,700,304 4,911,153
Other Income and Deductions 131,678 24,821
--------------------------
Income Before Interest Charges 5,831,982 4,935,974
Interest Charges 1,409,466 1,306,472
--------------------------
Net Income $4,422,516 $3,629,502
==========================
Weighted Average Number of Common Shares Outstanding 3,681,837 3,612,262
==========================
Earnings Per Share of Common Stock (1):
Net income $1.20 $1.00
$1.04
============ ============
FULLY DILUTED EARNINGS PER SHARE OF COMMON STOCK==========================
Fully Diluted Earnings Per Share of Common Stock (1):
Net income $0.95 $0.98$1.15 $0.96
==========================
The accompanying notes are an integral part of these financial statements.
(1) See Exhibit 11 - Computation of Primary and Fully Diluted Earnings
Per Share
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
FOR THE QUARTER ENDED
MARCH 31,For the Six Months Ended
June 30,
1995 1994
------------ ------------
OPERATING ACTIVITIES--------------------------
Operating Activities
Net Income $3,658,431 $3,746,087$4,422,516 $3,629,502
Adjustments to reconcile net income to net operating cash
Depreciation and amortization 1,408,387 1,427,9952,827,420 2,810,899
Deferred income taxes, net (440,967) (601,425)(788,893) (1,124,102)
Investment tax credit adjustments (8,823) (13,704)(22,527) (27,408)
Employee benefits 99,030 411,21870,813 495,962
Employee compensation from lapsing stock 216,885 184,125
restrictions 103,508 91,707
Reserve for refund 219,611 195,000282,240 820,011
Other (646,012) (383,283)(609,401) (1,287)
Changes in assets and liabilities:
Accounts receivable (362,791) (1,619,833)1,046,177 2,212,316
Inventory, materials, supplies and storage gas 2,547,027 2,805,2421,606,637 1,431,179
Prepaid expenses 378,859 196,319(47,224) 2,301
Other deferred charges 257,759 (117,717)389,950 (219,939)
Accounts payable (2,206,759) (1,290,386)(1,148,674) (1,978,518)
Refunds payable to customers 264,518 457,12790,427 171,537
Overrecovered purchased gas costs 673,148 1,488,4501,425,658 3,003,587
Other current liabilities 2,405,044 3,072,326
------------ ------------2,270,661 2,601,368
--------------------------
Net cash provided by operating activities 8,349,970 9,865,123
INVESTING ACTIVITIES12,032,665 14,011,533
Investing Activities
Property, plant and equipment expenditures, net (2,348,040) (1,822,634)(5,856,261) (4,050,084)
Purchases of investments, net (38,826)
------------ ------------(38,836)
--------------------------
Net cash used by investing activities (2,386,866) (1,822,634)
FINANCING ACTIVITIES(5,895,097) (4,050,084)
Financing Activities
Common stock dividends net of amounts reinvested of
$100,937$225,484 and $96,806,$196,065, respectively (702,763) (671,834)(1,406,342) (1,368,588)
Net repayments under line of credit agreements (5,000,000) (7,900,000)(4,500,000) (8,900,000)
Proceeds from issuance of treasury stock 69,843 61,157147,608 85,100
Repayments of long-term debt (186,080) (128,946)(518,580) (451,446)
Payments under capital lease obligations (27,616)(46,476)
Converted debenture bonds 4,984
------------ --------------------------------------
Net cash used by financing activities (5,819,000) (8,662,255)
NET INCREASE (DECREASE) IN CASH 144,104 (619,766)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD(6,277,314) (10,676,426)
Net Decrease in Cash (139,746) (714,977)
Cash and Cash Equivalents at Beginning of Period 398,751 1,162,797
------------ ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $542,855 $543,031
============ ============
The accompanying notes are an integral part--------------------------
Cash and Cash Equivalents at End of these financial statements.Period $259,005 $447,820
==========================
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
1. Quarterly Financial Data
The financial information included herein is unaudited. However,unaudited; however, the
financial information reflects normal recurring adjustments, which are, in
the opinion of management, necessary for a fair presentation of the
Company's interim results. Due to the seasonal nature of the Company's
business, there are substantial variations in the results of operations
reported on a quarterly basis. Certain amounts in 1994 have been
reclassified to conform with the 1995 presentation.
2. Investments
- Accounting Standard Adopted
The investment balances at March 31,June 30, 1995 and December 31, 1994 consist
primarily of an investment in the common stock of Florida Public Utilities
Company ("FPU"). The Company's ownership at March 31,June 30, 1995 and December 31,
1994, represents a 7.09%7.06% and 6.84% interest, respectively.
The Company has classified its investment in FPU as an "available for sale"
security, which requires that all unrealized gains and losses be excluded
from earnings and be reported as a separate component of stockholders'
equity, net of income taxes. At March 31,June 30, 1995 the market price per share,
cost basis per share, and the unrealized loss on the investment in FPU were
$18.75,$17.75, $20.05 and $133,680,$236,412, respectively. In management's opinion, the
decline in the value of the stock is temporary. At December 31, 1994 the
market price per share, cost basis per share and the unrealized loss were
$16.125, $20.20 and $401,609, respectively.
3. Statement of Financial Accounting Standards No. 121
In March 1995, the Financial Accounting Standards Board issued Statement of
Accounting Standards ("SFAS") No. 121 regarding accounting for asset
impairments. This statement, which must be adopted by the Company by
January 1, 1996, requires that long-lived assets be reviewed for impairment
whenever events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable. Additionally, the standard
requires rate-
regulatedrate-regulated companies to write-off regulatory assets to
earnings whenever those assets no longer meet the criteria for recognition
of a regulatory asset as defined by SFAS No. 71, Accounting for the Effects
of Certain Types of Regulation. Adoption of SFAS No. 121 is not expected
to have a material impact on the Company's financial statements.
4.4 Commitments and Contingencies
FERC Order No. 636
The Company is served by three direct natural gas pipelines: Columbia Gas
Transmission ("Columbia"), Transcontinental Gas Pipe Line Corporation
("Transco") and Florida Gas Transmission Company ("FGT"). Columbia and
Transco serve the Company's natural gas transmission subsidiary, Eastern
Shore, which in turn serves the Company's local distribution companies
("LDC") located in Delaware and Maryland. FGT serves the Company's LDC in
Central Florida. In connection with the issuance of Order No. 636 ("Order")
by the FERC in April 1992, pipelines will incur transition costs in
implementing the unbundled service requirement of the Order. In order to
recover prudently incurred transition costs from its customers, each pipeline
is required to file for, and obtain, FERC approval. Eastern Shore, based on
FERC proceedings involving the recovery of gas purchased and related costs,
believes that transition costs passed on from pipelines will be similarly
recoverable through the Eastern Shore PGA mechanism for their FERC regulated
sales. Eastern Shore also has direct sales customers whose rates are
currently not regulated. All transition costs allocated to these non-
regulated sales would be required to be expensed when known and measurable.
The Company is unable to estimate Eastern Shore's portion of any future
transition costs that may be assigned by Transco and Columbia until FERC
approves their request for recovery. In the opinion of management, it is not
possible to determine the effect, if any, that any transition costs incurred
in the future would have on Eastern Shore's financial position or results of
operations. FGT has incurred transition costs, which were subsequently
approved by FERC, for invoicing over a five-year period starting on November
1, 1993. Consequently, the Company recorded a liability and an equivalent
regulatory asset, since the Company expected, and did receive in 1994,
approval to recover the cost through the PGA. The regulatory asset and
equivalent liability balances at March 31, 1995 and December 31, 1994 are
$1,983,000 and $1,840,000, respectively.
FERC PGA
On May 19, 1994, the FERC issued an Order directing Eastern Shore to
refund, with interest, what the FERC characterized as overcharges from
November 1, 1992 to the current billing month. The Order also directed
Eastern Shore to file a report showing how the refund was calculated, and
to revise tariff language clarifying the PGA provisions of its tariff.
Eastern Shore filed a request for rehearing of the Order on June 20, 1994
based on what Eastern Shore believes is the FERC's erroneous interpretation
of Eastern Shore's tariff. It is Eastern Shore's position that the FERC's
Order essentially requires a retroactive change to the FERC approved PGA
procedures which Eastern Shore has consistently applied over the last six
years.
On June 21, 1994, in compliance with the FERC's Order, Eastern Shore filed:
(1) revised tariff sheets clarifying its PGA methodology and (2) two
alternative refund calculations based on the FERC's Order. The two
alternatives were filed due to what Eastern Shore believes to be an
inconsistency or contradiction with respect to the FERC's language in its
Order. On July 18, 1994 the FERC issued an "Order Granting Rehearing
Solely for the Purpose of Further Consideration." Such Order was issued
only to afford the FERC additional time for consideration of the issues
raised in Eastern Shore's request for rehearing. As of the date of this
report, the FERC has not approved either of the alternative refund
calculations submitted by Eastern Shore and has not made a final
determination as to Eastern Shore's request for rehearing. The Company is
currently negotiating with thewaiting for FERC to resolverule on the issue. The total accrued
liability at March 31,June 30, 1995 and December 31, 1994 are $1,494,000$1,526,000 and
$1,239,000, respectively.
Other Commitments and Contingencies
The Company and its subsidiaries are involved in certain legal actions and
claims arising in the normal course of business. The Company is also
involved in certain legal and administrative proceedings before various
governmental agencies concerning rates. In the opinion of management,
ultimate disposition of these proceedings will not have a material effect
on the consolidated financial position of the Company.
Environmental Matters
Dover Gas Light Company Site
In 1984, the State of Delaware notified the Company that a parcel of land
it purchased in 1949 from Dover Gas Light Company, a predecessor gas
company, contains hazardous substances. The State also asserted that the
Company is responsible for any clean-up and prospective environmental
monitoring of the site. The Delaware Department of Natural Resources and
Environmental Control ("DNREC") investigated the site and surroundings,
finding coal tar residue and some ground-water contamination.
In October 1989, the Environmental Protection Agency Region III ("EPA")
listed the Dover Site on the National Priorities List under the
Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA" or "Superfund"). UnderAt this time, under CERCLA, both the State of
Delaware and the Company arewere named as potentially responsible parties
("PRP") for clean-up of the site. In July 1990, the Company entered into
an agreement with EPA and DNREC to perform a Remedial
Investigation/Feasibility Study under the supervision of EPA and DNREC to
study the site and surroundings to determine any environmental impacts.
Pursuant to the agreement, the Company agreed to pay for the study and 80%
of the EPA's oversight costs. The Company submitted its reports on the
Remedial Investigation ("RI") and Feasibility Study ("FS") to EPA and DNREC
onin January 25, 1993 and February 15, 1993, respectively. The Company
receivedAfter receiving extensive
comments, from EPA and DNREC on the RI and FS reports. The Company submitted to the EPA and DNREC its revised RI and FS
reports onin May 14, 1993 and June 25, 1993, respectively. In the FS Report, Chesapeake
proposed a remedy which involved capping the site and monitoring ground-
water quality in the surrounding area. Chesapeake's consultantarea with a total estimated that it would cost of
approximately $700,000 to execute this plan of
remediation.$700,000.
After further discussions with the regulatory authorities, Chesapeake
agreed
to undertakeundertook an additional phase study, the Ground Water Evaluation Study -
Phase III, which focused on delineating the area of maximum ground-water
impact from the site. The results of that study were submitted to EPA and
DNREC in September 1993. On February 1, 1994, EPA issued its proposed plan
of action (the "Plan"). The Plan adopted many findings of the Phase III
Study, acknowledging that the Dover Site has only impacted ground-water in
a limited area.
The Plan presented and discussed a number of remedial alternatives,
including the remedial strategy proposed by the Company in the FS. The EPA
Plan proposed a more extensive remediation strategy that involved removal
of contaminated soils from the site and drilling a series of twenty (20)
wells. EPA estimated that execution of its Plan would cost $4.9 million.
The Plan was submitted by the EPA for public comment. The 30-day30 day public comment period, which
ended on April 4, 1994. During this period, the EPA received public
comments, including those submitted by the Company.
The EPA issued the site Record of Decision ("ROD") dated August 16, 1994.
The remedial action selected by the EPA in the ROD differed significantly
from the Plan. The EPA selected a less stringent ground-water remediation
addressing the ground-water contamination with a combination of hydraulic containment and
natural attenuation. Remediation selected for the soil at the site is to
meet stringent clean-up standards for the first two feet of soil and less
stringent standards for the soil below two feet. These selected levels of
remediation were not alternatives listed in the Plan, but utilized elements
proposed. In addition, the ROD incorporated many of the public comments
that were received. The ROD estimates the costs of selected remediation of
ground-water and soil at $2.7 million and $3.3 million, respectively. The
remediation selected in the ROD is substantially more limited than had been
suggested in the Plan. In the ROD, the EPA indicated that its previous
$4.9 million estimate was incorrect.
On November 18, 1994, EPA issued a "Special Notice Letter" (the "Letter")
to Chesapeake and three other PRPs. The Letter included, inter alia, (1) a
demand for payment by the PRPs of EPA's past costs (currently estimated to
be approximately $300,000) and future costs incurred overseeing site work;
(2) notice of EPA's commencement of a 60-day moratorium on certain EPA
response activities at the Site; (3) a request by EPA that Chesapeake and
the other PRPs submit a "good faith proposal" to conduct or finance the
work identified in the ROD and (4) proposed consent orders by which
Chesapeake and other parties may agree to perform the good faith proposal.
In January 1995, Chesapeake submitted to the EPA a good faith proposal to
perform a substantial portion of the work set forth in the ROD, which was
subsequently rejected.
It is unknown whether other PRPs will submit good
faith proposals, what such proposals might include and whether EPA would
accept such proposals. Under CERCLA, the EPA may reject any of the
proposals, and seek an administrative or order to require any or all of the
PRPs to implement the work. EPA may also do the work itself and seek
recovery of its costs in court.
The Company and the EPA are each attemptingattempted to secure voluntary performance of
part of the remediation by other parties. These parties include the State
of Delaware, which is the owner of the property and was identified in the
ROD as a PRP, and a business identified in the ROD as a PRP for having
contributed to ground-water contamination. On March 6, 1995, in order to
protect its interests, the Company filed suit in U.S. District Court for
the District of Delaware for a determination that the State of Delaware is
a liable party and for recovery from the State of costs of complying with
the ROD. The Company is also considering suit against other PRPs.
In addition,On May 17, 1995, EPA issued an order to the Company under section 106 of
CERCLA (the Order ), which requires the Company to fund or implement the
site ROD issued by EPA on August 6, 1994. The Order was also issued to
General Public Utilities Corporation, Inc. ( GPU ), which EPA and the
Company believe is liable under CERCLA. Other PRPs such as the State of
Delaware were not ordered to perform the ROD. EPA may seek judicial
enforcement of its Order, as well as significant financial penalties for
failure to comply. Although notifying EPA of objections to the Order, the
Company agreed to comply. GPU has statedinformed EPA that it will take stepsdoes not intend to
secure prompt commencementcomply with the order.
The Company has commenced the design phase of the remedial design phase neededwork required by the
Order. On July 6, 1995, the Company also submitted to implementEPA a study that
proposes two alternative remedies for the soil at the site. The
alternatives contemplate a reduction in the level and cost of soil cleanup
from that identified in the ROD. The alternatives are consistent with a
prior agreement by the State of Delaware that limits construction on the
site. The EPA is currently evaluating the proposal, which is supported by
the State of Delaware, and the Company therefore anticipates further negotiations on
this issue.
The litigation commenced by the Company on March 6, 1995 against the State
of Delaware remains pending in U.S. District Court for the District of
Delaware. The Company is currently engaged in discovery related to any
additional parties who may be PRPs. Based upon this discovery, the Company
will consider suit against other PRPs. Additionally, the Company and EPA
each continue to attempt to secure voluntary funding or performance of part
of the remediation by other PRPs. The Company expects continued
negotiations with PRPs to attempt to resolve these matters among the parties
and with the government. Management is evaluating the ROD to determine the
most economic approach to implementation of the remedies selected in the ROD.matters.
In the third quarter of 1994, the Company increased its accrued liability
recorded with respect to the Dover Site to $6.0 million from $700,000.
This amount reflects the EPA's present estimate, as stated in the ROD, for
remediation of the site according to the ROD. Future developments in the
matters discussed above would be accompanied by appropriate reductions to
the liability recorded as they occur. The Company also increased the
corresponding regulatory asset to $6.0 million. If the Company incurs
expenses of that amount in connection with undertaking the remedies
selected in the ROD, management's belief is that the Company will be
equitably entitled to contribution from other responsible parties for the
greater part of these expenses. Management also believes that any amounts
not so contributed will be recoverable in the Company's rates.
As of March 31,June 30, 1995, the Company has incurred approximately $3,177,000$3.2 million in
costs relating to environmental testing and remedial action studies. In
1990, the Company entered into settlement agreements with a number of
insurance companies resulting in proceeds to fund a portion of actual
environmental costs incurred over a five to seven-year period beginning in
1990. The final insurance proceeds were requested and received in 1994.
On February 23, 1993, the Delaware Public Service Commission, consistent
with prior base rate proceedings, authorized the Company to amortize an
additional $749,971 in environmental expenses for ratemaking purposes over
a seven-year period. At March 31,June 30, 1995 the unamortized balance is
approximately $527,000.$500,000. Of the $3,177,000$3.2 million in costs reported above,
approximately $305,000$328,000 has not been recovered through insurance proceeds or
received ratemaking treatment. It is management's opinion that these costs
incurred will be recoverable in future rates.
Salisbury Town Gas Light Site
In cooperation with the Maryland Department of the Environment ("MDE"), the
Company has completed an assessment of the Salisbury manufactured gas plant
site. The assessment determined that there was localized contamination of
ground-water. A remedial design report was submitted to MDE in November
1990 and included a proposal to monitor, pump and treat any contaminated
ground-
waterground-water on-site. The Company has proposed toThrough negotiations with the MDE, to proceed with these
activities over a maximum period of five years, after which time any residual
environmental impacts from the site will be reevaluated. The remedial design
was approved by MDE by a letter dated July 20, 1992, subject to certain
conditions stated in that letter. The Company responded by a letter dated
August 6, 1992, objecting to certain conditions imposed by MDE. In January
1993, after negotiations between the Company and MDE, the monitoring portion
of the remedial design was revised. MDE has approved additional revisions to the remedial
action workplan was revised with final approval from MDE obtained in early
1995. The remediation process for ground-water was revised from pump-and-
treat to Air Sparging and Soil-Vapor Extraction, resulting in a substantial
reduction in overall costs. The Company hopes to have the overall cost of this project. The MDE has approved the final remediation
processes called Air Spargingfacilities for ground water designed and Soil-Vapor Extraction for treating the
ground-water at the site.constructed by year-end.
The cost of remediation is estimated to be approximately $250,000$365,000 in
capital costs with yearly operating expenses of approximately $125,000.$200,000.
Based on theseearlier estimated costs, the Company recorded both a liability and
a deferred regulatory asset of $642,092 on December 31, 1994 to cover the
Company's projected remediation costs for this site. In July, the Company
will be increasing both the liability and deferred regulatory asset to
reflect the increase in costs. The liability payout for this site is
expected to be over a five-year period. As of March 31,June 30, 1995, the Company
has incurred approximately $1,799,000$1,725,000 for remedial actions and
environmental studies and has charged such costs to accumulated
depreciation. In a previous rate proceeding, the Company requested and
received recovery for all costs incurred as of November 30, 1988 through
base rates, including both a ten-year amortization of these costs and rate
base treatment for the unamortized balance. As of March 31,June 30, 1995, the
unamortized balance was approximately $190,000$179,000 and will be fully amortized
by May 31, 1999. In January 1990, the Company entered into settlement
agreements with a number of insurance companies resulting in proceeds to
fund a portion of actual environmental costs incurred over a three to five-yearfive-
year period beginning in 1990. The final insurance proceeds were requested
and received in 1992. Of the $1,799,000$1,725,000 in costs reported above,
approximately $841,000$767,000 has not been recovered through insurance proceeds or
received ratemaking treatment. It is management's opinion that these costs
incurred and future costs incurred, if any, will be recoverable in future
rates.
Winter Haven Coal Gas Site
The Company is currently conducting investigations of a site in Winter
Haven, Florida, where the Company's predecessors manufactured coal gas
earlier this century. A Contamination Assessment Report ("CAR") was
submitted to the Florida Department of Environmental Protection ("FDEP") on
July 11, 1990. The CAR contained the results of additional investigations
of conditions at the site. These investigations confirmed limited soil and
ground-water impacts to the site. By letter dated March 26, 1991, FDEP
directed the Company to conduct additional investigations on-site to fully
delineate the vertical and horizontal extent of soil and ground-water
impacts.
Additional contamination assessment activities were conducted at the site
in late 1992 and early 1993. On March 25, 1993, a Contamination Assessment
Report Addendum ("CAR Addendum") was delivered to FDEP. The CAR Addendum
concluded that soil and ground-water impacts have been adequately
delineated as a result of the additional field work. The FDEP approved the
CAR and CAR Addendum in March of 1994. The next step is a Risk Assessment
("RA") and a Feasibility Study ("FS") on the site. The RA and FS are expected tomay be
filed with the FDEP during the second quarterhalf of 1995 at an estimated cost of
$54,000.$60,000. Until the RA and FS are completed and accepted as final by the
FDEP, it is not possible to determine whether remedial action will be
required by FDEP and, if so, the cost of such remediation.
The Company has spent approximately $600,000 as of March 31, 1995, on these investigations as of
June 30, 1995 and expects to recover these expenses, as well as any future
expenses, through base rates. These costs have been accounted for as
charges to accumulated depreciation. The Company requested and received
approval from the Florida Public Service Commission ("FPSC") approval to amortize
through base rates $359,659 of clean-up and removalall costs incurred as of December 31, 1986.
As of December 31, 1992, these costs were fully amortized. In January
1993, the Company received approval to recover through base rates
approximately $217,000 in additional costs related to the former
manufactured gas plant. This amount represents recovery of $173,000 of
costs incurred from January 1987 through December 1992, as well as
prospective recovery of estimated future costs, which had not yet been
incurred at that time. The FPSC has allowed for amortization of these
costs over a three-year period and provided for rate base treatment for the
unamortized balance. In a separate docket before the FPSC, the Company has
requested and received approval to apply a refund of 1991 overearnings of
approximately $118,000 against the balance of unamortized environmental
charges incurred as of December 31, 1992. As a result, these environmental
charges were fully amortized as of June 1994. Of the $600,000 in costs
reported above, all costs have received ratemaking treatment. The FPSC has
allowed the Company to continue to accrue for future environmental costs.
At March 31,June 30, 1995, the Company has $40,000$49,000 accrued. It is management's
opinion that future costs above the amount accrued, if any, will be
recoverable in future rates.
Smyrna Coal Gas Site
On August 29, 1989 and August 4, 1993, representatives of DNREC conducted
sampling on property owned by the Company in Smyrna, Delaware. This
property is believed to be the location of a former manufactured gas plant.
Analysis of the samples taken by DNREC show a limited area of soil
contamination.
OnIn November 2, 1993 DNREC advised the Company that it would require a
remediation of the soil contamination under the state's Hazardous Substance
Cleanup Act and submitted a draft Consent Decree to the Company for its
review.Act. The Company met with DNREC personnel in December 1993 to
discuss the scope of any remediation of the site, and onin January 3, 1994,
submitted a proposed workplan, together with comments on the draft Consent
Decree. Initial comments from DNREC on the Work Plan were received onin
March 2, 1994, appropriatedappropriate revisions were prepared and the Work Plan was
resubmitted. Several additional sets of comments on the Work Plan were
received from DNREC
and theDNREC. The final Work Plan was submitted on September 27,
1994. DNREC has approved the Work Plan and the Consent Decree.
Remediation based on the Work Plan is scheduled to beginhas begun in 1995 at aan estimated cost
of approximately $75,000.$200,000. It is management's opinion that these and any
other costs will be recoverable in future rates.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS FOR THE
QUARTER ENDED MARCH 31, 1994JUNE 30, 1995
The Company recognized net income of $3,658,431$764,085 for the three months ended March
31,June
30, 1995, representing a decreasean increase in net income of $87,656$880,669 as compared to
the corresponding period in 1994. As indicated in the table below, the
decreaseincrease in earnings before interest and taxes ("EBIT") is due to lower earnings by the
natural gas and propane distribution segments partially offset by higher
earnings fromor a reduction in loss before interest and taxes ("LBIT") by all
segments of the natural gas transmission and the information technology
services segments.Company.
FOR THE QUARTER ENDED MARCH 31,JUNE 30,
1995 1994 Change
Earnings Before Interest and Taxes
Natural Gas Distribution $3,292,063 $3,336,505 $(44,442)$652,420 $544,147 $108,273
Natural Gas Transmission 848,008 724,601 123,4071,416,056 250,135 1,165,921
Propane Distribution 2,005,087 2,784,988 (779,901)(362,243) (429,190) 66,947
Information Technology Services
and Other 290,301 (13,616) 303,917184,649 (14,971) 199,620
Eliminations (73,646) (197,306) 123,660
---------(63,234) (103,145) 39,911
--------- ------- ---------
Total EBIT 6,361,813 6,635,172 (273,359)1,827,648 246,976 1,580,672
Operating Income Taxes 2,030,851 2,312,567 (281,716)458,306 (341,574) 799,880
Interest 716,791 640,582 76,209692,675 665,890 26,785
Non-Operating Income, Net 44,260 64,064 (19,804)
---------87,418 (39,244) 126,662
--------- ------- ---------
Net Income $3,658,431 $3,746,087 $(87,656)$764,085 $(116,584) $880,669
========= ======= ========= =======
Natural Gas Distribution
The natural gas distribution segment reported EBIT of $3,292,063$652,420 for the firstsecond
quarter of 1995 as compared to $3,336,505EBIT of $544,147 for the corresponding period last
year, a decreasean increase of $44,442.$108,273. The decreaseincrease in EBIT is due to a decreasean increase in
gross margin in all of our northern service territories, being partially offset by an
increase in gross margin and operating expenses in our Florida service territory.expenses.
FOR THE QUARTER ENDED MARCH 31,JUNE 30,
1995 1994 Change
Revenue $17,728,656 $20,816,188 $(3,087,532)$10,720,619 $10,718,471 $2,148
Cost of Gas 11,187,655 14,237,170 (3,049,515)6,839,884 7,160,811 (320,927)
---------- ---------- ----------------
Gross Margin 6,541,001 6,579,018 (38,017)3,880,735 3,557,660 323,075
Operations & Maintenance 2,095,538 2,154,035 (58,497)2,163,143 2,049,641 113,502
Depreciation & Amortization 596,368 530,894 65,474603,259 537,530 65,729
Other Taxes 557,032 557,584 (552)
---------- ----------461,913 426,342 35,571
--------- --------- -------
EBIT $3,292,063 $3,336,505 $(44,442)
========== ========== ==========$652,420 $544,147 $108,273
========= ========= =======
The decreaseincrease in revenue and cost of gasgross margin is primarily due to a decreasean increase in firm sales in
our northern service territories due to cooler than normal spring temperatures which were 10%
warmer
in the firstsecond quarter of 1995 when compared to the corresponding period inof
1994. Partially offsetting this decrease wasIn addition, our Florida service territory had an increase in our Florida service
territory's deliveries to phosphate customers as well as
transportation sales to two co-generation facilities that began operations in
April and July of 1994.
The decreaseincrease in operations and maintenance expenses of $58,497$113,502 is due to a
decrease in employee pensions and benefits. This was partially offset by an
increase in legal feescustomer accounting expenses, mains, meter and less administrative expenses being capitalized as
part of utility plant.house regulating
equipment. Depreciation and amortization expenses increased $65,474$65,729 due to
plant placed in service during the past year. Other taxes increased $35,571
primarily due to an increase in property and payroll taxes.
Natural Gas Transmission
The natural gas transmission segment reported EBIT of $848,008$1,416,056 for the
firstsecond quarter of 1995 as compared to $724,601EBIT of $250,135 for the corresponding
period last year, an increase of $123,407.$1,165,921. The increase in EBIT is due to
an increase in gross margin and a decrease in operating expenses.
FOR THE QUARTER ENDED MARCH 31,JUNE 30,
1995 1994 Change
Revenue $9,722,685 $11,958,622 $(2,235,937)$10,256,182 $7,868,230 $2,387,952
Cost of Gas 7,992,312 10,309,195 (2,316,883)7,887,217 6,626,019 1,261,198
---------- --------- ---------- ---------
Gross Margin 1,730,373 1,649,427 80,9462,368,965 1,242,211 1,126,754
Operations & Maintenance 607,611 662,904 (55,293)684,852 733,147 (48,295)
Depreciation & Amortization 174,239 174,445 (206)
Other Taxes 100,515 87,477 13,038
---------93,818 84,484 9,334
---------- --------- ---------
EBIT $848,008 $724,601 $123,407$1,416,056 $250,135 $1,165,921
========== ========= ==========
=========
The decreaseincrease in revenue and cost of gas is primarily due to a 27%106% increase in
industrial interruptible sales volumes. This was partially offset by a 17%
decrease in the commodity cost of gas which is passed on to our customers. The increase
in gross margin is primarily dueattributable to a 6%the increase in industrial interruptible sales volumes
as natural gas competed favorably with alternative fuels. This was
partially offset by a reductionThe increase in
industrial interruptible sales is primarily due to increased sales to the
methanol plant, a large
industrial interruptible customer.plant. Sales volumes and margins forto this customer were down 20%up 153% and
42%168%, respectively, when compared to the same period last year. Adding to the
increased gross margin is a $549,000 reduction in the amount expensed in 1995
to accrue for a potential refund, when compared to the corresponding period in
1994 (see note 4 to the Consolidated Financial Statements). Of the $549,000
reduction in 1995, $412,000 was a one-time expense in June 1994 to fully
accrue for a refund ordered by FERC.
The decrease in operations and maintenance expenses of $55,293$48,295 is due to a
decreasedelay in employee pensionsthe painting of a structure and benefits, as well asreduction in cathodic related
maintenance expenses relatedin the second quarter of 1995 when compared to mains, measuring and regulating stations and communication equipment.the same
period of 1994. Other taxes increased $13,038$9,334 due to plant placed in service
during the past year and payroll related taxes.
an increase in pipeline safety assessments from the
federal government.
Propane Distribution
TheFor the second quarter of 1995, the propane distribution segment recognized EBITexperienced a
LBIT of $2,005,087$362,243. These results were more favorable than those achieved for
the firstcorresponding quarter of 1995. As compared to EBIT forin 1994, with the first quarter of 1994, these
results representsegment recognizing a decrease in
earningsLBIT of $779,901,$66,947, or 28%. Generating16%, over the second quarter 1994 LBIT of $429,190.
Slightly over one-half of this decrease in EBITLBIT was aattributable to an
increased gross margin, with the remaining decline in gross margin, offset minimally byLBIT being a direct
result of reduced operating expenses.
FOR THE QUARTER ENDED MARCH 31,JUNE 30,
1995 1994 Change
Revenue $7,333,899 $8,671,583 $(1,337,684)$2,503,533 $3,168,118 $(664,585)
Cost of Gas 3,506,842 4,055,116 (548,274)1,248,735 1,949,889 (701,154)
--------- --------- ----------------
Gross Margin 3,827,057 4,616,467 (789,410)1,254,798 1,218,229 36,569
Operations & Maintenance 1,382,201 1,379,582 2,6191,215,342 1,226,412 (11,070)
Depreciation & Amortization 323,525 341,500 (17,975)325,485 338,320 (12,835)
Other Taxes 116,244 110,397 5,84776,214 82,687 (6,473)
--------- --------- ---------
EBIT $2,005,087 $2,784,988 $(779,901)-------
LBIT $(362,243) $(429,190) $66,947
========= ========= ================
Revenues and cost of gas decreased in 1995, when compared to the same period
in 1994 due to sales in 1994 to a wholesale customer under a non-recurring
contract. The decreaseincrease in gross margin wasresulted from a combination of volume2% increase in sales
volumes, coupled with a 5% increase in the average margin per gallon. The
increase in gallon sales directly related to a larger customer base and
slightly colder temperatures. The rise in the average margin per gallon
corresponded to a higher selling prices.
Forprice per gallon, partially offset by a
higher cost per gallon. Selling prices are adjusted in response to demand and
competition. Regional market prices for propane did not drop as far in the
firstsecond quarter of 1995, gallons sold were 15% lower thanas compared to 1994, resulting in a higher propane
cost for the first
quarter of 1994. This decrease in volumes was a direct result of the average
temperature being 10% warmer than the same period last year. Furthermore, the
timing and magnitude of the colder temperatures in the first quarter of 1994
were not repeated in 1995. Selling prices were lower due to competition and the
lack of demand generated by warmer temperatures.segment.
Operations and maintenance expenses increased $2,619decreased by $11,070, or 1%, largely as a
result of higher
sellinglower vehicle maintenance, advertising and general and administrative salaries, as well as increased
maintenance costs for repairs to the delivery fleet, some of the bulk storage
facilities and idle propane tanks. Offsetting these increased expenses were
lower pension and benefit costs.insurance expenses.
Depreciation and amortization decreaseddropped by $17,975,$12,835, or 5%4%, as many of the vehiclesassets obtained in
a prior acquisitionsacquisition became fully depreciated. Other taxes increased $5,847,also declined
$6,473, or 5%8%, as a direct result of the increased sellinglower real estate and general and administrative salaries.personal property taxes.
Information Technology Services and Other
For the quarter ended March 31, theThe information technology services and other segment recognized an EBIT of
$290,301$184,649 and a LBIT of $14,971 for the second quarters ended June 30, 1995 and
a loss before interest and
taxes ("LBIT") of $13,616 for 1994.1994, respectively. This increase in EBIT of $303,917$199,620 is the
result of increasedattributable to
higher revenues and lower operating expenses.
FOR THE QUARTER ENDED MARCH 31,JUNE 30,
1995 1994 Change
Revenue $2,292,514 $2,201,250 $91,264$2,070,528 $1,909,460 $161,068
Operations & Maintenance 1,671,944 1,815,614 (143,670)1,578,630 1,604,208 (25,578)
Depreciation & Amortization 237,142 304,838 (67,696)232,671 255,919 (23,248)
Other Taxes 93,127 94,414 (1,287)74,578 64,304 10,274
--------- --------- -------
EBIT/LBIT $290,301 $(13,616) $303,917$184,649 $(14,971) $199,620
========= ========= =======
ComprisingHigher consulting and programming training, resource placement, facilities
management, hardware and consulting and programming revenues contributed to
the overall increase in revenues of $91,264 were higher training revenues and
a sale of Page-IT, the segment's billing software product for the
telecommunications industry.$161,068, or 8%. Partially offsetting
these increasedhigher revenues was reduced system software revenue, as well as the
absence of any Currin and Associates, Inc. ( C&A ) revenues due to its
dissolution in 1994. Included in the second quarter results were reduced revenues on hardware. Inherent within the results$413,028 and
$556,138 of the first quarters
of 1995 and 1994, respectively, were intercompany revenues of $452,090 and
$673,279 and intercompany profits of $73,646 and $197,306. The intercompany
revenues represented 20% and 31% of the total segment's revenues for the first
quarters of 1995 and 1994, respectively. BothOf these
total intercompany revenues, $63,236 and $103,144 corresponded to intercompany
EBIT for 1995 and 1994, respectively. The decline in intercompany revenues
from 1994 to 1995, and therefore, intercompany EBIT, illustrates the intercompany revenue and
profit were down due to approximately halfdrop in
development time as many hours being spent onUtiliCISTM, the
development of UtiliCIS, a customer information and billing system
duringfor the first quarter of 1995, as compared to the same periodCompany s natural gas distribution segment, is in 1994. Of the hours
dedicated to UtiliCIS, a greater percentage have been worked by outside
contractors on which CDS earns no margin on intercompany sales. UtiliCISits implementation
stage. UtiliCISTM is scheduledexpected to be implemented in the Company's natural gas division officescompleted in 1995.
Operations and maintenance expenses decreased $143,670,declined $25,578, or 8%2%, primarily due to
the absence of $73,166$63,135 of expenses incurred by C&A in 1994 (see Note 3 to the
Consolidated Financial Statements), as well as reduced hardware expense and employee benefits. Hardware expense was down in response to a corresponding
decline in hardware revenue. Employee benefits fell due to employee sharing of
benefitlower health
care and pension costs. These decreased expenses were partially offset by
increased laborexpenses in areas such as payroll and training costs, a direct result ofhardware, which are directly
associated with the increased revenue.revenues. Depreciation and amortization
expenses declined $67,696,$23,248, or 22%9%, due to certain pieces of
hardware becommingmore assets becoming fully depreciated and the
C&A's&A s dissolution. Other taxes rose $10,274, or 16%, in response to the
higher payroll costs.
Interest
The increase in interest expense is associated with higher short-term
borrowing balances, as compared to the same period last year, and higher
interest rates on those balances.
Non-Operating Income
The decreaseincrease of approximately $20,000$127,000 in the second quarter 1995, as compared
to the corresponding quarter in 1994 is primarily the absence of the 1994
after tax write-off of our investment in Currin and Associates, Inc.,
slightly offset by a decrease in 1995 interest income.
Operating Income Taxes
Income taxes increased due to higher second quarter EBIT, as compared to last
year, and the elimination of the valuation allowance for state operating loss
carryforwards associated with the Company's propane segment. The Company
projects the utilization of all state operating loss carryforwards generated
by the propane segment in the early 1990's.
RESULTS OF OPERATIONS FOR THE
SIX MONTHS ENDED JUNE 30, 1995
The Company recognized net income of $4,422,516 for the six months ended June
30, 1995, representing an increase in net income of $793,014 as compared to
the corresponding period in 1994. As indicated in the table below, the
increase in EBIT is due to a higher gross margin by the transmission segment
offset by a reduced gross margin by the propane segment.
FOR THE SIX MONTHS ENDED JUNE 30,
1995 1994 Change
Earnings Before Interest and Taxes
Natural Gas Distribution $3,944,483 $3,880,652 $63,831
Natural Gas Transmission 2,264,064 974,736 1,289,328
Propane Distribution 1,642,844 2,355,798 (712,954)
Information Technology Services
and Other 474,950 (28,587) 503,537
Eliminations (136,880) (300,451) 163,571
--------- --------- ---------
Total EBIT 8,189,461 6,882,148 1,307,313
Operating Income Taxes 2,489,157 1,970,995 518,162
Interest 1,409,466 1,306,472 102,994
Non-Operating Income, Net 131,678 24,821 106,857
--------- --------- ---------
Net Income $4,422,516 $3,629,502 $793,014
========= ========= =========
Natural Gas Distribution
The natural gas distribution segment reported EBIT of $3,944,483 for the first
six months of 1995 as compared to EBIT of $3,880,652 for the corresponding
period last year, an increase of $63,831. The increase in EBIT is due to an
increase in gross margin in our service territories, partially offset by an
increase in operating expenses.
FOR THE SIX MONTHS ENDED JUNE 30,
1995 1994 Change
Revenue $28,449,275 $31,534,659 $(3,085,384)
Cost of Gas 18,027,540 21,397,980 (3,370,440)
---------- ---------- ---------
Gross Margin 10,421,735 10,136,679 285,056
Operations & Maintenance 4,258,681 4,203,676 55,005
Depreciation & Amortization 1,199,626 1,068,424 131,202
Other Taxes 1,018,945 983,927 35,018
---------- ---------- ---------
EBIT $3,944,483 $3,880,652 $63,831
========== ========== =========
The decrease in revenue and cost of gas is primarily due to a decrease in firm
sales in our northern service territories due to temperatures which were 5%
warmer in the first two quarters of 1995 when compared to the corresponding
period of 1994. Partially offsetting this decrease, was an increase in sales
to phosphate customers and two co-generation facilities in our Florida
division.
The increase in operations and maintenance expenses of $55,005 is due to an
increase in maintenance to mains, customer installation expenses, engineering,
customer accounting expenses and less administrative expenses transferred to
plant. This was partially offset by a decrease to outside services and
employee pension and benefits. Depreciation and amortization expenses
increased $131,202 due to plant placed in service during the past year.
Natural Gas Transmission
The natural gas transmission segment reported EBIT of $2,264,064 for the first
six months of 1995 as compared to EBIT of $974,736 for the corresponding
period last year, an increase of $1,289,328. The increase in EBIT is due to
an increase in gross margin and a decrease in operating expenses.
FOR THE SIX MONTHS ENDED JUNE 30,
1995 1994 Change
Revenue $19,978,867 $19,826,852 $152,015
Cost of Gas 15,879,530 16,935,214 (1,055,684)
----------- ---------- ---------
Gross Margin 4,099,337 2,891,638 1,207,699
Operations & Maintenance 1,292,462 1,396,051 (103,589)
Depreciation & Amortization 348,478 348,890 (412)
Other Taxes 194,333 171,961 22,372
---------- ---------- ---------
EBIT $2,264,064 $974,736 $1,289,328
========== ========== ==========
The increase in revenue is primarily due to a 64% increase in industrial
interruptible sales volumes which was offset by a 24% decrease in the cost of
gas which is passed on to our customers. The increase in gross margin is
attributable to the increase in interruptible sales volumes as natural gas
competed favorably with alternative fuels. The increase in industrial
interruptible sales is primarily due to increased sales to the methanol plant.
Sales volumes and margins to this customer were up 78% and 84%, respectively,
when compared to the same period last year. Adding to the increased gross
margin is a $549,000 reduction in the amount expensed in 1995 to accrue for a
potential refund, when compared to the corresponding period in 1994 (see note
4 to the Consolidated Financial Statements). Of the $549,000 reduction in
1995, $412,000 was a one-time expense in June 1994 to fully accrue for a
refund ordered by FERC.
The decrease in operations and maintenance expenses of $103,589 is due to a
reduction in employee benefits and the delay in the painting of structures and
reduction in cathodic related maintenance expenses in the second quarter of
1995 when compared to the same period of 1994. Other taxes increased $22,372
due to plant placed in service during the past year, an increase in pipeline
safety assessments from the federal government and payroll related taxes.
Propane Distribution
The propane distribution segment recognized EBIT of $1,642,844 for the first
six months of 1995. As compared to EBIT for the six months ended June 30,
1994, these results represent a decline in earnings of $712,954, or 30%.
Producing this decrease in EBIT was a lower gross margin, offset slightly by
reduced operating expenses, particularly depreciation and amortization.
FOR THE SIX MONTHS ENDED JUNE 30,
1995 1994 Change
Revenue $9,837,432 $11,839,701 $(2,002,269)
Cost of Gas 4,755,577 6,005,005 (1,249,428)
--------- ---------- ----------
Gross Margin 5,081,855 5,834,696 (752,841)
Operations & Maintenance 2,597,542 2,605,994 (8,452)
Depreciation & Amortization 649,011 679,820 (30,809)
Other Taxes 192,458 193,084 (626)
--------- ---------- ---------
EBIT $1,642,844 $2,355,798 $(712,954)
========= ========== =========
The decrease in gross margin resulted from an 11% decline in sales volumes, as
well as a 2% decrease in the average margin per gallon. The decrease in
gallon sales resulted from average temperatures in 1995 being 5% warmer than
the corresponding period in 1994. Furthermore, the magnitude and timing of
the colder temperatures experienced in the first quarter of 19951994 did not recur
in 1995. The decrease in the average margin per gallon corresponded to a
higher cost per gallon, which was due toonly partially offset by higher selling
prices.
Operations and maintenance expenses decreased by $8,452, just under 1%, as a
result of lower advertising, pension and benefits, and insurance expenses.
Depreciation and amortization decreased by $30,809, or approximately 5%, as
various assets obtained in a prior acquisition became fully depreciated.
Information Technology Services and Other
For the recording of a loss on the sale of certain real property insix months ended June 30, the information technology services and
other segment recognized an EBIT of $474,950 and a LBIT of $28,587 for 1995
and 1994, respectively. This increase in EBIT of $503,537 is the outcome of
higher revenues and lower operating expenses.
FOR THE SIX MONTHS ENDED JUNE 30,
1995 1994 Change
Revenue $4,363,042 $4,110,710 $252,332
Operations & Maintenance 3,250,574 3,419,823 (169,249)
Depreciation & Amortization 469,813 560,757 (90,944)
Other Taxes 167,705 158,717 8,988
--------- --------- -------
EBIT/LBIT $474,950 $(28,587) $503,537
========= ========= =======
Comprising the increase in revenues of $252,332 were higher consulting and
programming training, resource placement and consulting and programming
revenues, as well as a sale of Page-ITTM, the segment s billing software
product for the telecommunication industry. Partially offsetting these higher
revenues were reduced hardware sales. Of the total revenues for the six
months ended June 30, 1995 and 1994, $865,098 and $1,229,417, respectively,
represented intercompany revenues. The intercompany EBIT associated with
these revenues are eliminated in consolidation; these amounts totalled
$136,881 and $300,451 for 1995 and 1994, respectively. The intercompany
revenue and EBIT amounts for the six months ended June 30, 1995 continued to
decline over the prior year as less time is being spent on the development of
UtiliCISTM, a customer information and billing system designed for the
Company s natural gas distribution segment. UtiliCISTM is in an
implementation stage, with completion scheduled in 1995.
Operations and maintenance expenses declined $169,249, or 5%, primarily due to
the absence of $136,301 of expenses incurred by C&A in 1994. Despite
recognizing significant decreases in such expenses as health care, pension and
hardware, these reductions were partially offset by increases in other
operations expenses, primarily payroll. Payroll rose in response to increased
revenues. Depreciation and amortization declined $90,944, or 16%, due to
certain pieces of hardware becoming fully depreciated and the dissolution of
C&A. Other taxes increased $8,988, or 6%, as a result of higher payroll
costs.
Interest
The increase in interest expense is associated with higher short-term
borrowing balances, as compared to the same period last year, and higher
interest rates on those balances.
Non-Operating Income
Non-operating income increased approximately $107,000 as compared to the same
period in 1994, primarily due to the absence of the 1994 after tax write-off
of our investment in Currin and Associates, Inc., slightly offset by a
decrease in 1995 interest income.
Operating Income Taxes
Income taxes decreasedincreased due to lower first quarterhigher 1995 EBIT, as compared to last year, and
the elimination of the valuation allowance for state operating loss
carryforwards associated with the Company's propane segment. The Company
projects the utilization of all state operating loss carryforwards generated
by the propane segment in the early 1990's.
Environmental Matters
The Company continues to work with federal and state environmental agencies to
assess the environmental impacts and explore corrective action at several
former gas manufacturing plant sites (see Note 4 to the Consolidated Financial
Statements). The Company believes that any future costs associated with these
sites will be recoverable in future rates.
FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES
The Company'sCompany s capital requirements reflect the capital intensive nature of its
business and are attributable principally to its construction program and the
retirement of its outstanding debt. The Company relies on funds provided by
operations and short-term borrowings to meet normal working capital
requirements and temporarily finance capital expenditures. During the first
threesix months of 1995, the Company'sCompany s net cash flow provided by operating
activities, net cash used by investing activities and net cash used by
financing activities were approximately $8,350,000, $2,387,000$12,033,000, $5,895,000 and
$5,819,000,$6,277,000, respectively. Due to the seasonal nature of the Company'sCompany s
business, there are substantial variations in the results of operations
reported on a quarterly basis.
The Board of Directors has authorized the Company to borrow up to $14,000,000
from banks and trust companies. As of March 31,June 30, 1995, the Company had four
$8,000,000 unsecured bank lines of credit. Funds provided from these lines of
credit are used for short-term cash needs to meet seasonal working capital
requirements and to fund portions of its capital expenditures. The
outstanding balances of short-term borrowings at March 31,June 30, 1995 and 1994 were
$3,000,000$3,500,000 and $1,000,000,$0, respectively.
On July 6, 1995, the Company entered into an agreement for the private
placement of $10,000,000 of 6.91% Senior Notes due in 2010. It is anticipated
that funding on these Senior Notes will occur in October 1995. The Company
will use the proceeds to retire $4,091,000 of the 10.85% Senior Notes of
Eastern Shore Natural Gas Company, originally due October 1, 2003, and to
repay short-term borrowing under the Company s lines of credit.
During the threesix months ended March 31,June 30, 1995 and 1994, net property, plant and
equipment expenditures were approximately $2,348,000$5,856,000 and $1,823,000,$4,050,000,
respectively. For 1995, the Company has budgeted $16.6 million for capital
expenditures. The components of this amount include $11.9 million for natural
gas distribution, $1.7 million for natural gas transmission, $1.8 million for
propane distribution, $1.0 million for Skipjack, Inc.structures and the remaining $200
thousand$200,000
for computer equipment. The natural gas and propane expenditures are for
expansion and improvement of their existing service territories. The
expenditures for Skipjack are for construction and improvements. Financing of
the 1995 construction will be provided primarily by short-term borrowings and
cash from operations. The construction program is subject to continuous
review and modification by management. Actual construction expenditures may
vary from the above estimates due to a number of factors including inflation,
changing economic conditions, regulation, load growth and the cost and
availability of capital.
The Company expects to incur environmental related expenditures in the future
(see Note 4 to the Consolidated Financial Statements), a portion of which may
need to be financed through external sources. Management does not expect such
financing to have a material adverse effect on the financial position or
capital resources of the Company.
As of March 31,June 30, 1995, common equity represented 62.5%62.9% of permanent
capitalization, compared to 60.4% as of December 31, 1994. The Company
remains committed to maintaining a sound capital structure and strong credit
ratings in order to provide the financial flexibility needed to access the
capital markets when required. This commitment, along with adequate and
timely rate relief for the Company'sCompany s regulated operations, helps to ensure
that the Company will be able to attract capital from outside sources at a
reasonable cost. The achievement of these objectives will provide benefits to
customers and creditors, as well as the Company'sCompany s investors.
PART II
OTHER INFORMATION
CHESAPEAKE UTILITIES CORPORATION AND SUBSIDIARIES
Item 1: Legal Proceedings
See Note 4 to Financial Statements
Item 2: Changes in Securities
None
Item 3: Defaults Upon Senior Securities
None
Item 4: Submission of Matters to a Vote of Security Holders
NoneThe Annual Meeting of Stockholders was held on May 16, 1995.
Proposals as submitted in the proxy statement were voted on as
follows:
1. All Board of Director nominees were elected to the classes
indicated in the proxy statement.
2. The Chesapeake Utilities Corporation Directors Stock
Compensation Plan was approved.
3. Amendments to the Company s Certificate of Incorporation (the
Certificate) for the purpose of modernizing the Certificate
was approved.
4. Amendments to the Certificate authorizing 2,000,000 shares of
preferred stock was approved.
5. Amendments to the Certificate changing the number of Directors
to a number to be determined by the Board was defeated.
6. Ratification of the selection of the Company s independent
auditors through the fiscal year ending December 31, 1995 was
approved.
Item 5: Other Information
None
Item 6(a): Exhibits
Exhibit 10(a)3 - Executive Employment Agreement dated March 26, 1995,
by and betweenCertificate of Incorporation of Chesapeake Utilities
Corporation and Jeremy D. West,
filed herewith.
Exhibit 10(b) - Executive Employment Agreement dated March 26, 1995,
by and between Chesapeake Utilities Corporation and Philip S.
Barefoot,is filed herewith.
Exhibit 11 - Computation of Primary and Fully Diluted Earnings Per
Share is submitted herewith.
Item 6 (b): Reports on Form 8-K
None
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
CHESAPEAKE UTILITIES CORPORATION
/s/ John R. Schimkaitis
- -----------------------
John R. Schimkaitis
Senior Vice President and Assistant Treasurer
(Principal Financial and Accounting Officer)
Date: May 11,August 15, 1995